To produce oil or gas, a well is drilled into a subterranean formation that is an oil or gas reservoir.
Generally, well services include a wide variety of operations that may be performed in oil, gas, geothermal, or water wells, such as drilling, cementing, completion, and intervention. Well services are designed to facilitate or enhance the production of desirable fluids such as oil or gas from or through a subterranean formation. A well service usually involves introducing a well fluid into a well.
Natural resources such as gas, oil, and water in a subterranean formation are usually produced by drilling a wellbore down to the subterranean formation while circulating a drilling fluid in the wellbore. After terminating the circulation of the drilling fluid, a string of pipe, e.g., casing, is run in the wellbore. The drilling fluid is then usually circulated downward through the interior of the pipe and upward through the annulus, which is located between the exterior of the pipe and the walls of the wellbore. Next, primary cementing is typically performed whereby a cement slurry is placed in the annulus and permitted to set into a hard mass (i.e., sheath) to thereby attach the string of pipe to the walls of the wellbore and seal the annulus. The main objectives of primary cementing operations include zonal isolation to prevent migration of fluids in the annulus, support for the casing or liner string, and protection of the casing string from corrosive formation fluids. Subsequent secondary cementing operations may also be performed. Secondary or remedial cementing operations are performed to repair primary-cementing problems or to treat conditions arising after the wellbore has been constructed.
Oil or gas in the subterranean formation may be produced by driving fluid into the well using, for example, a pressure gradient that exists between the formation and the wellbore, the force of gravity, displacement of the fluid using a pump or the force of another fluid injected into the well or an adjacent well. The production of fluid in the formation may be increased by hydraulically fracturing the formation. That is, a viscous fracturing fluid may be pumped down the casing to the formation at a rate and a pressure sufficient to form fractures that extend into the formation, providing additional pathways through which the oil or gas can flow to the well.
Fluids used in drilling, completion, or servicing of a wellbore can be lost to the subterranean formation while circulating the fluids in the wellbore. In particular, the fluids may enter the subterranean formation via depleted zones, zones of relatively low pressure, lost circulation zones having naturally occurring fractures, weak zones having fracture gradients exceeded by the hydrostatic pressure of the drilling fluid, and so forth. The extent of fluid losses to the formation may range from minor (for example less than 10 bbl/hr) referred to as seepage loss to severe (for example, greater than 500 bbl/hr) referred to as complete loss. As a result, the service provided by such fluid is more difficult to achieve. For example, a drilling fluid may be lost to the formation, resulting in the circulation of the fluid in the wellbore being too low to allow for further drilling of the wellbore. Also, a secondary cement or sealant composition may be lost to the formation as it is being placed in the wellbore, thereby rendering the secondary operation ineffective in maintaining isolation of the formation.
Lost circulation treatments involving various plugging materials such as walnut hulls, mica, and cellophane have been used to prevent or lessen the loss of fluids from wellbores. The disadvantages of such treatments include the potential for damage to subterranean formations as a result of the inability to remove the plugging materials and the dislodgement of the plugging materials from highly permeable zones whereby fluid losses subsequently resume.
One technique for preventing lost circulation problems has been to temporarily plug voids or permeable zones with Sorel cement compositions. Sorel cement compositions typically comprise magnesium oxide, a magnesium chloride salt, and water, which together form, for example, magnesium oxychloride hydrate. Sorel cements can be removed, if desired, with minimal damage to subterranean zones or formations by dissolution in acids.
Sorel cement use has been limited, however, by the fact that formations that are sensitive to water, such as those containing swelling clay or shale, cannot be exposed to water-based wellbore servicing fluids such as a Sorel cement slurry because of the potential for sloughing of the formation material into the wellbore. Consequently, such wellbores are typically drilled with oleaginous fluids such as oil-based drilling fluids.
In addition, the commercialization efforts for such Sorel cement compositions have been hampered by the settling of magnesium chloride suspended in an oil-based fluid before reaching the well site or while sitting at the well site prior to use. For the Sorel cement composition to set, the magnesium oxide, magnesium chloride, and water need to be combined within a particular range of weight or molar ratios. Settling of one of the components causes the reactants to be present in non-stoichiometric amounts, thereby preventing proper setting of the composition.
It would be desirable to develop Sorel cement compositions that are based on non-aqueous carrier fluids, compatible with oleaginous fluids, that are stable to storage without settling of the magnesium chloride, and that then begin to set when exposed to an aqueous fluid in the well.